Faster ways to find the right video Acoustic fibre optics in wells What you can do with seismic in the cloud Is better subsurface knowledge the key to improving the financial viability of offshore operations? February / March 2015 Issue 53 Official publication of Finding Petroleum 015 vents 22014 EEvents Non-seismic Geophysics London, 19 Feb 2015 Finding Enough Oil & Gas in NW Europe London, 12 Mar 2015 Transforming Sub-Surface Interpretation Aberdeen, 17 Mar 2015 Doing more with Subsurface Data Aberdeen, 18 Mar 2015 Transforming Sub-Surface interpretation London, 13 Apr 2015 Doing more with Subsurface Data Stavanger, 05 May 2015 Doing more with Production Data Stavanger, 06 May 2015 Finding Oil in Atlantic Basins London, 27 May 2015 n issio m d A £20 m o r f Find out more and reserve your place at www.d-e-j.com Find out more and reserve your place at www.findingpetroleum.com www.d-e-j.com Deeper knowledge leads to wider opportunities by David Bamford If we do not act quickly, the UK Continental Shelf (UKCS) and Norwegian Continental Shelf (NOCS) will soon be on life support. Issue 53 February / March 2015 Naturally, first reactions have been “Give us a Tax break!” and “How do we get Costs way down?” Future Energy Publishing Ltd Yes, these are important because they finish up in the Numerator of the crude economic equation that describes profitability. 39-41 North Road, London, N7 9DP, UK www.d-e-j.com Tel +44 (0)208 150 5292 Fax +44 (0)207 251 9179 But there is also a Denominator which is, or are, barrels of oil or cubic feet of gas. How do we input more of these into the equation? Editor Karl Jeffery [email protected] Tel +44 208 150 5292 I have two thoughts: Beginning with a story. Many years ago I had a minor role in BP’s takeover of Britoil (previously of course BNOC, the UK government’s national oil and gas company). Conference Producer Panas Kalliantas [email protected] Tel +44 208 150 5295 This takeover was underpinned by profound understanding of North Sea geology, of Yetto-Find volumes, of undeveloped discoveries, of upcoming development projects, of producing fields. Advertising, event sponsorship and Exhibitions Manager In point of fact, BP probably understood Britoil’s acreage and fields better than Britoil did itself. Richard McIntyre [email protected] Tel +44 (0) 208 150 5291 This 1986 – 1988 work was almost entirely analogue – paper composite logs, paper seismic sections, hand-drawn maps, tracing paper, light-tables, occasional use of the “digitizing table” (remember those?). It worked! Production Wai Cheung [email protected] Subscriptions: £250 for personal subscription, £795 for corporate subscription. E-mail: [email protected] Today it is difficult, impossible actually, to see such a profound underpinning anywhere, perhaps because lots of key individuals have ‘moved on’, perhaps because of lazy assumptions that the North Sea’s best days are somehow behind it. And yet the significant Johan Sverdup discovery in the NOCS, in a well-explored area, was as I understand it, the result of deep geological knowledge and innovative thinking. We know perfectly well how to do these things – see for example this summary of how work on Nova Scotia revitalised exploration there. www.qz.com/318755 Something similar, of similar scope and imagination, is needed for the North Sea and, arguably, NW Europe as a whole. Somehow this has to be a ‘multi-client’ study, driven and delivered by oil and gas industry folk, not some academic or research exercise. Secondly, we geoscientists have developed a lazy dependence on ‘yet-another-towedstreamer-3D-seismic-survey’ which we need to move beyond. There are all sorts of new technologies ‘out there’, from seismic nodes, passive seismic, fibre optics, full tensor gravimetry, electromagnetics, that can tell us much more about the sub-surface, bringing better predictions, and higher volume successes. In principle, digital technology should allow us to be more efficient and effective in integrating diverse sources of existing data and new multi-measurements, thereby allowing coherent interpretation from the scale of whole basins to individual producing reservoirs. This ‘deeper knowledge’ will indeed lead to ‘wider opportunities’. Front cover art by Alex McKenzie, artist, Digital Energy Journal Just one snag…….. I haven’t yet seen a digital offering that can do this! Printed by Printo, spol. s r.o., 708 00 Ostrava-Poruba, Czech Republic. www.printo.cz David Bamford is a director of Digital Energy Journal and Finding Petroleum, and a non-executive director of Premier Oil February / March 2015 - digital energy journal 1 Leaders Repsol and IBM - “cognitive” computing in E+P Spanish oil major Repsol is working together with IBM to build a $15m-$20m system to answer difficult questions about which licenses to bid for and how to optimise production, using experts together with big data By Santiago Quesada, Repsol’s director for exploration and production technology develop cognitive technologies that can analyse subsurface data in order to drive improvements in exploration and production. ing cognitive limitations posed by big data. Scientists in the CEL will also experiment with a combination of traditional and new interfaces which are based upon gesture, robotics and advanced visualisation and navigation techniques. Based at IBM's pioneering Cognitive Environments Laboratory (CEL), the researchers will work on two prototype applications which are specifically designed to increase Repsol's strategic decision-making in the optimisation of oil reservoir production and in the acquisition of new exploration areas and production fields, both onshore and offshore. Through these modalities, researchers can leverage sophisticated models of human characteristics, preferences and biases that may be present in the decision-making process. Oil companies continue to make high-stake decisions in the face of increasing uncertainty and geological risk based on extremely complex data sets. Repsol is making an initial investment of $15 million to $20 million to develop two applications with early results targeted for late 2015. The technology will also introduce new realtime factors which should be considered such as current news events around economic instability, political unrest and natural disasters. Cognitive computing systems can help in exploration and production by helping individuals to better interpret big data and then make informed decisions based on that data. The team will work together in New York and Madrid, with each company committing six to 10 employees to develop the technology. As a result, companies can maximise access to better exploration areas, increase the productivity of maturing oil fields and their value, enhance safety and mitigate environmental risks. People, devices and spaces These tools are not intended to replace the key stakeholders such as geologists, geophysicists, engineers, investment managers, risk analysts and corporate strategists, but to assist them with building more fluid conceptual and geological models, highlighting the impact of the potential risks and uncertainty, visualising trade-offs and exploring what-if scenarios. Santiago Quesada, Repsol’s director for exploration and production technology Until recently, geoscientists have been tasked with mostly manually reading and extracting information from enormous amounts of data including journal papers reports, seismic data and models of reservoirs, wells and facilities. Recognising the need for an intelligent solution, Repsol and IBM, leveraging years of existing collaboration, recently teamed up to To best achieve this, the cognitive computing technology infrastructure has been designed to specifically interact with people across various devices and physical spaces. For example, the technology is able to process questions asked by humans in natural language and sifts through information to respond with the most likely answers. This, in turn, will enable individuals and teams to make better decisions by overcom- The new applications developed by Repsol and IBM will improve the way oil companies visualise and develop exploration and production activities. It is envisioned that companies from other sectors will set up their own CELs to make better informed decisions and, ultimately, increase their companies’ bottom lines. Oceaneering’s Video Vault - faster video retrieval Oceaneering has developed the Video Vault cloud-based solution to make it easier to store, share and find the right piece of subsea and offshore video Subsea engineering company Oceaneering has launched a cloud-based live video streaming and archiving solution called Video Vault to make it easier to store, retrieve, view, share and analyze the video you are looking for. To simplify future video retrieval and analysis, video files can be tagged geographically, with comments or subtitles, or according to the time it was recorded. This means you can 2 develop systems to quickly pull up video relating to a certain location or operational significance, and view both real time and historical data. The use of video in offshore operations, for both subsea and surface monitoring, has grown massively in recent years, and brought a lot of challenges for finding the right video image from hours of video files, says digital energy journal - February / March 2015 Subsurface Mark Stevens, Director of CommunicationsGDS, Oceaneering. Usually Oceaneering has about 100 simultaneous video feeds across the company. The data files are getting larger all the time, with more high definition and 3D cameras and high-resolution video compression formats. Meanwhile there are many limitations to physical media (such as DVDs, USB drives). It is hard to manage and share files. Common Operating Picture (COP) Oceaneering’s core aim is to help oil and gas personnel create a ‘Common Operating Picture’. This is a term which originated in the military, which means a view of all of your operations on a (usually large screen) map, where you can drill in to see what you need. you can automatically bring up the video inspection image of a certain section of pipeline. A lot of companies are asking for video of drilling data, particularly looking at the drill floor, to record the drill pipe going through the floor of the drill ship and back out again. Viewing the data In terms of viewing the data, about 30 per cent of clients use mobile devices. “That continues to be the trend,” Mr Stevens said. It means staff can monitor offshore activities from wherever they are, so less staff are required to be actually offshore. To search for video on Video Vault, you start with a Google Earth or ESRI map interface. The Common Operating Picture serves as a dashboard of all of your activity, showing the locations of all your vessels and rigs. When video is added to the COP, users can click on any of numerous monitored assets to see associated recorded video. You can see all the live video streams with a location on the map, or you can draw a box around an area and see all the video you have for that region. You can browse the entire video library with advanced search, preview and indexing, using thumbnails to speed identification of interest areas, and then play back selected video with the convenience of fast- and slow-forward, fast- and slow-rewind, and pause capabilities. You can view a thumbnail of all your real time video streams, displayed in the appropriate position of the map, refreshed every 30 seconds. Clients often ask to connect different files to the video at appropriate points (such as pdf documents and pictures), which you can do with metadata content management. You can say “show me all the video in the Gulf of Mexico”, then click on an individual ROV in that area and say “follow”. You can provide usage data such as which employees were watching the video and how much bandwidth they consumed, as well as total bandwidth utilization across the organization. Some oil companies (including Statoil) have their own 3D visualisation platform, and can view this data in the COP, as well. Benefits of video Oil and gas companies are using video in many different ways. Subsea, companies use video for monitoring ROV operations, observing rotary brush cleaning operations, subsea X-ray imaging (digital radiography) and general long term asset monitoring. The video is proving particularly useful in subsea cleaning work. You can capture videos before and after cleaning, to see how effective the cleaning was, and then work out a better cleaning schedule. If the video is of a pipeline inspection, all of the video can be geographically tagged, so There are tools to deliver a short video file to your desktop – so if you want to watch a 5 minute section of a 4 hour video, you don’t need to download the whole thing. Archival infrastructure The Video Vault solution is made available as a hosted cloud service for a tiered, dailyrate or monthly price depending on application, including maintenance. It is also available as a bundled hardware solution for on premise installation. This means you can store the data on your local servers, or you can host it on a standard commercial archival service like Google. Clients never have to see any physical storage media. If you are concerned about storing your data on standard commercial cloud services, you could use Video Vault with Amazon’s “Gov- Have a “Common Operating Picture” of your operations - drill down to get further information and live video Cloud” service, designed specifically for more sensitive data. Open standards / commercial systems are used as much as possible (including integration with Google Earth and ESRI) to give clients as much flexibility as possible. There are “application programming interfaces” (APIs) enabling you to connect Video Vault with other software tools. There are 10 software developers working on the project, out of a total team of 55 developers at Oceaneering. Geospatial Data Integration Video Vault’s ability to integrate geospatial data means that the GPS co-ordinate of the asset being monitored is automatically embedded into the captured live video data stream. For subsea monitoring, the GPS coordinates of the topside vessel is used. For some subsea projects, transponders have been laid on the vessel floor, which enable the gathering of location information from the seabed. Larger ROVs have an internal inertial map (NAV) system, which estimate the ROV’s location based on how it is moving through the water. “It can calculate to within inches where the ROV is,” Stevens says. In June 2014, Oceaneering acquired a company called PortVision®, which has a vessel tracking service and 5 year database of vessel locations around the world derived from automatic identification systems (AIS)data. Oceaneering is now connecting the vessel information with the video – if you know about the date and which asset the camera was recording, you can put this together with AIS data to work out the location. February / March 2015 - digital energy journal 3 Subsurface Inova - mini-vibes, low fequency and UAVs Interesting recent developments in land seismic recording technology include ‘mini-vibes’, low frequency seismic, and UAVs for wireless seismic quality control, says Andy Bull, VP Product Development, Emerging Technologies at INOVA Geophysical. But we may be reaching the limit of the number of seismic channels we are able to record without significant advances in computing technology. INOVA has developed a range of small Vibroseis trucks, known as ‘mini-vibes’, which can create seismic energy in areas where standard Vibroseis trucks can’t go. The usual way to create seismic energy on land is by using large Vibroseis trucks which provide 60-80,000 lbs of force. Inova produces the UNIVIB and UNIVIB 2 Vibrator trucks, which provide up to 26,000 (UNIVIB) or 34,000 (UNIVIB 2) pounds of peak force, but have the advantage of being much easier to use in urban areas, or areas with more difficult terrain, said Andy Bull, VP Product Development, Emerging Technologies at INOVA Geophysical. He was speaking at the Finding Petroleum conference in London on November 26, “New E&P Technologies”. “These little (mini vibe) machines are capable of really nice manoeuvring, low environmental impact and tremendous broadband energy,” he said. “These machines can output super signals over a bandwidth of 1-400 Hz and at significant depth,” he said. In one example, data acquired in the South Georgia Rift Basin (USA), using 2 UNIVIBtrucks, with data at 6 to 76 Hz. “They have been able to bring out a structure at 10,000 feet,” he said. The market for mini-vibes is partly driven by the increased efforts oil companies have to make about to limit the environmental impact of exploration, he said. This includes thinking about how much line cutting (path clearing) they need to do, how much dynamite they are going to Mini vibroseis machines - "capable of really nice manoeuvring, low environmental use, and what to do about impact and tremendous broadband energy" wildlife. The environmental impact is further reduced if you use cable-less technology and small vibroseis trucks, he said. Because they have a shorter length and width, less line cutting is required, he said. They can also move up slopes of difficult terrain. INOVA Geophysical is a manufacturer of land seismic technology, formed from assets from ION Geophysical and BGP in March 2010. It produces a range of seismic recording equipment and seismic source equipment. Low frequency seismic INOVA is seeing an increasing customer interest in working with low frequency seismic. “We have been involved in several projects in various locations where we starting with frequencies as low as 1.5 Hz, and we think we can go down further,” he said. MEMS (Microelectromechanical systems) sensors are “ideal for [recording] this low frequency data,” he said. The sensor systems are designed to be small (107g), low power (85mW) and tightly integrated with acquisition systems. “We're still learning a lot about the benefits of these low frequencies.” Data acquired in the South Georgia Rift Basin (USA) using 2 UNIVIB trucks was able to bring out a structure at 10,000 feet 4 digital energy journal - February / March 2015 Mr Bull showed an example of data surveyed by Petroleum Development Oman (OMAN), where during the survey, the company decided to extend the bandwidth down to 1.5 Subsurface “By integrating UAV’s with cable-less systems, powerful status QC and noise monitoring can be achieved simply and even more efficiently without the need for complex radio infrastructure,” he said. But there are still regulatory obstacles to using UAVs in many countries though, he said. Big data Inova's G3i HD cabled seismic recording system - designed for high productivity Hz, and you can see how the data improves. You can see just the data generated from 1.5 – 6 Hz seismic and it is very clear. The company has also done some downhole testing with sensors recording at up to 7,500 feet, recording data as low as 0.5 Hz. Downhole data was also recorded at high frequencies, resulting in coherent 200 Hz energy visible at over 5,000 ft depth. Seismic technology market At the time of his talk in November 2014, Inova was already seeing oil and gas companies make reductions in their exploration programs due to cost constraints due to the low oil price, he said. But the Middle East is “still a healthy area. “There's a lot of investment still going on, a lot of surveys planned,” he said. Annual spending on seismic technology has been fairly flat for the past 10-15 years, with a small uplift in the mid-2000s with a move to larger surveys. “This creates difficulty for companies like ourselves,” he said. “We're helping the market acquire much more data, of better quality, but the volume of spend is not increasing. Many companies are starting to look seriously at broadband seismic acquisition, as they look for oil at greater depths, in more complex geology, and with better resolution images, he said. Or they want to do “full waveform inversion,” using the two-way wave equation to produce high resolution velocity models. Cabled and wireless In terms of land seismic acquisition systems, 80 to 85 per cent of new seismic system sales are still cabled, rather than cable-less. “The costs [of cabled systems] are reducing,” he said. “The cable system is still substantially less per channel than cable-less system.” Cabled systems like INOVA’s G3i HD need to be able to run surveys at all kind of scales, be integrated with other types of sensor (for example with waterborne sensors for ‘transition zone’ surveys), or used with cable-less, and productivity is very important. Keeping productivity high “is a huge focus for us,” he said. Meanwhile there is growing interest in cableless technology for environmental and safety reasons, he said. It requires smaller crews. The power consumption is reducing all the time, so now devices are capable of 20-30 days operation in the field from one battery charge. With a cable-less system like INOVA’s Hawk, you can do powerful quality control and noise monitoring simply, via wi-fi, he said. UAVs Companies are now showing interest in developing unmanned aerial vehicles (UAVs) which can fly around the spread of wireless devices, download data over wi-fi and do basic quality control on it, he said. Purchasing a fixed wing UAV, which can carry a 5 lb payload and fly for 2 hours, costs about $150,000, he said. But they might be able to quality control 910 lines in a 2 hour period, compared to 1-2 lines using conventional methods. There is a lot of talk about increasing the number of channels (individually recorded data streams) in a seismic survey, but people have perhaps not taken into consideration how they will communicate and store all the data, he said. With 250,000 channels, your data rate is 4 to 5 gigabits per second. “That's a tremendous amount of data coming up the cable. The system has got to handle this.” Typical tape drives can record 160 to 250 megabytes a second, and a solid state disk can store 500 to 600 megabytes a second. Disks in a “RAID” array could store 3 to 4 gigabytes per second. But your data recording speed can be reduced by many factors including the processor, input-output, memory, cache, quality control. “You see that throughput onto your recording device really comes down,” he said. “We’re right on the edge of what's capable and what's supportable in the field,” he said. “It’s a very big challenge - taking this acquisition up to 500,000 and beyond that.” In terms of data storage, 500,000 channels could generate up to 86 terabytes of data over 24 hours. Over 6 months, that’s 12 petabytes of data storage (one petabyte = 1000 terabytes). A petabyte costs about $250,000 today. “It’s a massive cost”, he said. “We're going to be really challenged to solve this.” “Maybe we'll see a bit of plateau of what people need in terms of channel count until they understand how to handle this volume of data.” View Andy Bull’s talk on video and download slides at www.findingpetroleum.com/video/1095.as px February / March 2015 - digital energy journal 5 Subsurface Getting more value from seismic In the current financial environment, oil companies need to improve the way they get maximum value from their seismic. Jane Hodson explained how to do this The best way to get the most value from seismic data is to have a strategy for managing the data at the beginning of the project, said Jane Hodson, head of technical services at DataCo, and formerly lead subsurface technologist with Centrica, speaking at the Digital Energy Journal Aberdeen conference on November 27, “Better ways to Manage Seismic Data”. “Who quality controls the seismic when it is uploaded? Is it the geophysicist? Is it the data manger?” “That will give a more value upfront than managing it at the end. “ “I've had people coming to me and Delegates at Digital Energy Journal's Nov 27 Aberdeen conference saying, 'I can’t see my seismic', "Better ways to manage seismic data" that they've loaded. I said, ‘You’ve loaded it in Norway, but it's in the UK sector, external one you need to make that decision. because you got the wrong UTM.’” So the rule is get it loaded by someone who actually “Companies spends millions acquiring seismic, and then they forget to do the critical knows how to do this not everyone has that publishing of the final piece of work.” skill. Good data management is a key to opening up that potential and we have excellent supply of subsurface data management expertise in Aberdeen, Ms Hodson said. “With this we can be a global player in this field, we have the domain knowledge, we have the people and we have the technology.” As well as reducing the amount of budget companies have available, the low oil price is also likely to drive company towards acquisitions, mergers and sales and even decommissioning, she said, which all leads to big demands on data. With this current downturn in the market we have to start looking at ways to work differently, work smarter, faster and work with the data we already have,” she said. Seismic data at the right time Having well managed seismic data starts with how the data is delivered into your system in the first place, she said. A key question is who in the company first receives the data. “Does new seismic data get delivered to your data management team, to the IM team, or does it go straight to the geophysicists?” she asked. “Does it get catalogued?” “How do you know that they have loaded it correctly or have QC it? It’s imperative this is done, because if it is not then this happens.” If you get the data catalogued, loaded, verified and ready to interpret then you have done your job right. “In the end it is essential you have a detailed catalogue of your data, whether that is seismic or well, or even documents. “ Dry wells or worse “Have your archive strategy in place, because you never know when you might need to access it again.” “If you don't get the process right things start to happen you wish had not.” “The geophysicist does his/her interpretation, creates all those lovely horizons and surfaces, and gives it to the geologist.” “The geologist creates the geological model, gives it to the reservoir engineer, and they all decide where to drill the well. They drill the well and then, oh, there's nothing there.” Back to the drawing board because you did not ensure the data was loaded correctly in the first place. Lost time, lost money and lost opportunity. Data verification and data integrity are key things to be completed before any interpretation work is carried out then hopefully you will have less failures. Publishing and Archiving “Is the seismic data delivered with everything attached, such as an acquisition report, or a loading sheet? If it doesn’t have a loading sheet, how do you know what all the data is?” Do you have the naming standards in place so you can identify the type of seismic you have? 6 Whether or not you find oil, the seismic interpretation data needs to be captured and published. “And when all this is done, and the entire package is been tied up quite neatly, the last bit is to archive or sell! Whether it is archiving in your own internal storage system or an digital energy journal - February / March 2015 “As a final statement it means in the future you can check your archives instead of spending another five million pounds or more on reshooting or purchasing seismic, when you may have it already.” IT “So the geophysicist is on the workstation, and wants to access the data, but [the network is] so slow it’s driving them crazy.” “You can do as much as you want to clean up those data, but if the [network] you have got is not up to the job, then what’s the point?” “Work with IT. Make sure that you have everything in place like network connectivity. So when the geophysicists are actually interpreting the data, they don't have to wait 10 minutes for each inline to display.” Geophysicists are a valuable commodity in themselves so wouldn’t you prefer they had the tools to deliver the projects on time then sit around waiting. You can view Jane’s talk on video at www.d-e-j.com/video/1228.aspx Subsurface OCTIO - business case for permanent reservoir seismic It may be easier to justify spending on permanent reservoir seismic if it is used for overburden monitoring, or monitoring drill cuttings injection, rather than to monitor the reservoir, says Helge Brandsaeter of Octio There have been a number of well publicised cases in Norway where a water injection well put more pressure into the rock than it was able to handle, leading to craters opening up in the subsea, he said. Fields in the Barents Sea have shallow reservoirs, so there is higher risk Octio produces a system with permanent digital cables on the seabed, which can make regular seismic surveys and monitor how the reservoir is changing. Using digital cables on the seabed, to record seismic data and get a picture of how the oilfield is changing as it is produced, is generally thought to enable an increase in oil and gas recovery of 5 per cent over the lifetime of the field, said Helge Brandsaeter, president of OCTIO, speaking at the Digital Energy Journal Stavanger conference on December 10, “People and Subsea Data”. But from an investment point of view, systems are not being installed because too often it is seen as ‘nice to have’ rather than a necessity, he said. “You see faulting going from the reservoir to surface directly,” he said. In reservoirs like this, “The overburden is as important as the reservoir." In Brazil, the overburden is “young in geological terms” which means that if water is injected at too high pressure you can open pre-existing faults to the seabed, and water and oil seeping to the seabed. By monitoring the seabed with digital cables, you can see how the rock is fracturing and if there is a chance the fracture will reach the surface. “It’s not difficult to see that seismic can map any such seepage,” he You can see how the cracks develop subsurface. “This will give the operational teams a notice that something has to be done by the injection,” he said. “It is reasonably easy to set up a business proposition which is reasonably sound,” he said. Drill cuttings The system is being used on the Oseberg field (140km Northwest of Bergen), to monitor the injection of drill cuttings and waste water. Drill cuttings are milled very finely at the platform and injected into the reservoir. This provides a much less expensive option for managing drill cuttings than transport back to land. “The average cost for a North Sea field for transportation of cuttings and water waste is close to $20m a year,” he said. “The alternative is to ensure safe injection, for $2m to 3m.” But Norway has “zero tolerance” for any waste pollution. “If you can't ensure safe injection you have to transfer all the fluids onshore,” he said. Seabed infrastructure Most oil and gas staff are busy meeting their short term objectives, and don’t have time for longer term ones. Octio typically installs a mesh of seismic sensors on the seabed, 50m apart, which communicate with a hub and send the data to surface. But the short term business case can be much stronger if you see it as a way to monitor the overburden (rock between the reservoir and seabed) and avoid costly environmental fines, he said. One system has 172 sensors in a W shape around the well on the seabed. The sensors have 4 components, 3 component accelerometers and hydrophones. Octio is majority owned by Statoil Technology Invest. Overburden problems The seismic recording can help spot problems leading to possible overburden leakage. Developing a better business case for permanent reservoir seismic monitoring: Helge Brandsaeter, president, OCTIO The sensors have an ‘active’ mode for recording seismic data in a survey, and a ‘passive’ mode for continually listening to seismic data. Everything is managed remotely, with data said. February / March 2015 - digital energy journal 7 Subsurface transmitted back to shore. The installation of the system basically comes down to the cost of leasing vessels, and installation cost is a third of the lifetime operating costs. The data communications infrastructure can also be used for any other subsea equipment. “If you build such an area wide infrastructure we can use it for all types of communications and types of sensors,” he says. “You can drop down a sensor and communicate to surface. “We have made basically an ethernet on the seafloor, you can interface any system to us,” he said. Octio is working with a number of standardisation committees including SWIG (Subsea Wireless Group) and SIIS (Subsea Instrumentation Interface Standardisation). Watch Helge’s talk on video at www.d-e-j.com/video/1502.aspx Using acoustic fibre optics in wells UK company Optasense reports that enormous progress is being made with using fibre optics in wells for recording seismic data, monitoring, fracking and flow, among other applications. Making progress with recording seismic in wells with fibre optic – David Hill, chief technology officer, Optasense Using fibre optics to record seismic data in wells has been done since 2010, but there has been enormous progress made since then, both with the technology and market acceptance, said David Hill, chief technology officer of UK company OptaSense, speaking at the Finding Petroleum London conference on Nov 26, “New E&P Technologies.” Seismic recording with optical fibre using a technique called Distributed Acoustic Sensing (DAS) in wells is not as sensitive as conventional geophones, but the target is to reach that level, he said. Some people say the oil and gas industry takes 30 years to adopt a new technology, but the technology has already been widely implemented in 5 years, he said. You don’t need to drill a special observation well, you just install a fibre-optic cable in an existing producer or injector well. If there is already a fibre-optic cable in the well (perhaps installed to monitor temperature), you can use that. The DAS technology has been used on one offshore well so far, operated by Shell in the Gulf of Mexico. Shell was conducting a large seismic survey in the region and wanted to see if it could get any value from a 8 fibre-optic cable which had been installed in one of the wells a few years ago for a different purpose, he said. “We were asked to attach our box to it, to see if we could get any usable seismic.” The recorded data was so good, that “one of our employees had to spend seven weeks on that platform, including over Christmas, recording 50,000 shots.” 1400 channels were recorded simultaneously, from two 6km fibres. In another project, in a mature field in Oman, the customer wanted to monitor where injected steam was going, so they could plan an infill well strategy. To do this fibre was installed in eight wells, a task which took about a month, and then a 3D DAS-VSP (Vertical Seismic Profile) was acquired simultaneously on each well The data was correlated and stacked as it was being recorded, enabling quality control do be done immediately. After seismic shooting, the data is being stitched together to get a field wide view, he said. The same system can be used for time lapse seismic, comparing a seismic survey today with the seismic survey at some time in the past. For this to work, the fibre probably needs to be fixed firmly in the well (cemented or attached to the casing or production string), not dangled on a wireline. The technology could also be used to monitor CO2 storage wells, he said. digital energy journal - February / March 2015 The repeatability of the recorded data helps people gain confidence in it, he said. The fibre can also be used for microseismic, recording natural seismic energy, which can also be used to understand the subsurface. Recording passive seismic data in an oil well is not a new idea. It is conventionally done, by drilling an observation well and inserting geophones in it, or installing the geophone in an existing well. The work is “risky and expensive”, he said. In one example, fibre was installed on a highly deviated well, which meant that by triangulation you could work out where the source was. Optasense currently has 180 employees and offices around the UK, Houston, Calgary, Dubai and Australia. It recently acquired two California based companies; RIO (Redfern Integrated Optics), which produces the special laser which sends the light through the fibre, and SR2020, a specialist in high definition borehole seismic imaging and interpretation. How it works The technology works by firing a pulse of light (laser) into the fibre. The glass fibre is “the purest material man has ever made,” but there is enough inhomogeneity in the molecular structure to cause a small amount of light backscatter, he said. The backscatter appears to be random, but it stays relatively constant if the fibre is not disturbed. Subsurface But if there is a tiny strain on the fibre, which can include a strain caused by a noise, the backscatter pattern changes slightly. With a calculation involving the speed of light, you can calculate which part of the fibre that event happened. rate of oil and see the trends. “The technology has nowhere near fulfilled its full capabiilty yet.” Sometimes wells gradually fill with water, and then the oil suddenly pushes past it, sending the water back into the reservoir. You can monitor what is happening across inflow control valves (ICVs) and at the gas lift values (GLVs) in order to make sure they are working properly. The processing work will typically divide a length of fibre into a number of sections and work out the sounds which could be heard at each section of the cable (so it is equivalent to one seismic channel). For example a 5km fibre can be split into 500 x 10m sections. You can also monitor pressure. “In the future we hope this technology will replace gauges downhole,” he said. The fibre can be installed by attaching it to the production string, or cemented behind the casing. It can also be run into the well on a wireline or slickline. It has been used on a well 7km long. The technology has been used to monitor electrical submersible pumps (ESPs), analysing the noise to see rotational speeds, and spot for any cavitation effects in the motor. The fibre-optic cables are very robust. “Fibre is actually stronger than steel,” he said. “These cables have been developed over 20 years.” In fracking, you can check the perforation charges are firing properly, and then monitor the flow through the perforations. You can also listen to what is happening with a frac job on a neighbouring well. The fibre-optic cable can handle temperatures of up to 300 degrees C. The fibre response is quite directional, and not so sensitive cross axis – so it cannot determine which direction a sound is coming from. One possible solution is to wind the fibre around the well, he said, or try to develop a perpendicularly sensitive cable. Fracking and flow The DAS acoustic data can be used to monitor what is happening in the well, including fracking operations, monitoring flow, water loading and valve operations. For example you can see a rising water level in the wells. You can also record the flow Sometimes frackers push proppant into an adjacent well, potentially blocking it, he said. It has been used to make sure plugs are set properly, because of a particular sound signature which is heard when a plug is set. Sometimes, the system detects wells having sudden leaks, releasing fluid at high pressure and then closing. This is something a standard sensor would probably not capture, he said. The system can’t get do multiphase flow measurements “but there are strong indications it might be possible,” he said. Data The company is trying to come up with a standard way to define the data, so the data can be transferred between systems. The data files can be enormous, with one well generating “a terabyte a day without any problem,” he says. “That's only going to get orders of magnitude worse as technology progresses.” To keep data files manageable, it is essential to process the data at source, so you are only transferring the much smaller processed data files, he said. In 2015, version 4 of the OptaSense DAS system will be made available, with an extra 6dB signal to noise improvement and better spatial resolution, he said. Other applications Optasense’s biggest business application for the technology so far is for pipeline monitoring. It is currently installed on 12,000 km of pipeline, to detect potentially damaging activity along the pipeline and detect leaks. The technology is also used to monitor and installed around factories to monitor for people climbing over or cutting fences. It is being used for condition monitoring, to monitor condition of risers. View a video of David’s talk at www.findingpetroleum.com/video/1060.aspx CGG - time for seismic on the cloud? For economic reasons if nothing else, the oil and gas industry is likely to start moving its seismic data to the cloud, says CGG’s Henri Blondelle Many companies in the retail and banking sector moved their data to the cloud in the period 2008-2009, driven by the need to reduce costs after the 2008 crisis, said Henri Blondelle, VP Global Business Development CGG Data Management Services. Perhaps now oil companies will move seismic data to the cloud for the same reason. He was speaking at the Digital Energy Journal conference in Aberdeen on November 27, “Better Ways to Manage Seismic Data”. The benefits of cloud data are well publicised, but perhaps none of them motivate activity as much as short term economic gain. The financial case of storing data on cloud servers, rather than on your own, is quite strong. If you want to store data in-house, your investment in buying storage equipment is initially quite high, followed by a small additional cost each year for new data storage. So your purchasing costs are uneven. You might choose to buy new equipment February / March 2015 - digital energy journal 9 Subsurface One seismic data has been moved to the cloud, you can gain many extra benefits, such as being able to do Hadoop processing and automatic data indexing - Henri Blondelle, global business development manager, CGG Data Management Services again after 3-5 years. Using a cloud or provider you can keep the cost the same every year, and the cost will also decrease as the cost of storage equipment decreases. You only pay for the storage you need, and can increase or decrease it on demand. “I have seen a lot of pilots, a lot of proof of concepts, which for me prove that the industry will be ready in the next few months to absorb this challenge [of putting seismic on the cloud],” he said. Once the data has been moved onto the cloud, the industry can gain many further benefits, already used by other industries, such as the ability to run Hadoop based interpretation on it, he said. CGG works together with Microsoft Azure as a cloud service provider, and proposes its customers a package with CGG Data Management services running over Microsoft Azure. Security and control Many oil and gas companies have chosen not to move data to the cloud due to security concerns, an argument made stronger by many recent cloud hacking stories. To try to mitigate these concerns, cloud service provider Microsoft Azure recently conducted a survey of its existing customers to ask them what they thought about security after having moved their data to the cloud. “All of them considered that the security, after moving to the cloud, is better than before,” Mr Blondelle said. “A majority (but not all) users consider that they have more control on the data on the cloud than with their previous (internally hosted) solution,” he said. There are many ways cloud service providers can improve security, such as storing data encrypted, ensure the security of the data centre, 10 and find ways to transfer the data securely, he said. Some companies might have legal requirements to store data in a certain country, or might choose not to put some data on the cloud because of slow internet connections. In one example, Statoil used Hadoop cloud storage to make correlations between changes in seismic data and pore pressure calculations. Well logs and drilling data Some of these problems can be resolved by having a partial cloud solution, he said. CGG ran a pilot project in mid-2014 together with Teradata mixing well logs and drilling data covering the whole of the North Sea. Of course the cloud system can make it much easier to provide other parties with access to your data as required, including governments and joint venture partners. It worked with a very difficult drilling data set, mainly pdfs of well reports, with mud density data on them. “It’s very difficult to extract this information from a pdf,” he said. Easier to work with The project team also tried to automatically extract data from well logs and well completion reports. One often overlooked advantage of putting seismic data in the cloud is that it is easier to work with in many ways, he said. For example, you can create automatic tools to monitor the quality of your data, and run business rules. One oil company has 6,000 business rules. You can display data from many different servers together, for example if you have separate databases for well logs and seismic data files. You can keep track of all the data processing tasks which have been done, which is very helpful if you have to discover an error somewhere in the process you want to roll back, and have had several interpreters working on data simultaneously. After extracting the data, efforts were made to try to find correlations. Some of the correlations were as expected. “The drillers know already the formations which are difficult to drill,” he said. But there was also some detailed information which could be very useful. “In this part of the North Sea, for this particular formation, if you use this particular mud density, you have 80 per cent of chance to have a bad hole section,” he said. “There is a possibility of bringing this quantitative information to the people who have to make a drilling program.” Indexing You can use sophisticated cloud based analytics tools which can interpret text. You can use analytics tools such as Tibco’s Spotfire or Tableau Software. These tools make it easy to share the results of the analytics – unlike if you do the analytics running over Petrel, which means that someone needs to login to a Petrel workstation to view them. Many interpreters “prefer to use something that looks like Excel - like Spotfire or Tableau,” he says. Teradata and Horton Works provide a range of statistical tools you can use. You can store your seismic data in a Hadoop based storage solution, which gives you the ability to do some Hadoop analytics without downloading the data, including all the seismic processing and interpretation. digital energy journal - February / March 2015 CGG has also looked at ways to make seismic data easier to catalogue and index automatically. Indexing data “the classical way” generally involves opening it, reading it, and entering the relevant information in a database, which can be time consuming, if you have millions of files to index. As a result the task is often not done. So perhaps if the documents could be analysed and indexed automatically, oil companies would index documents which otherwise would not be indexed at all. These tools are already used by US law firms to automatically classify reports on cases, he said. View Henri’s talk on video at www.d-e-j.com/video/1223.aspx Subsurface Using surprise in subsurface knowledge research Until now, enterprise search systems have focused on precision – helping you find exactly what you want. But our internet search engines are moving more and more towards other ways of guessing what you might want. And surprising you with what they find. Should enterprise search move in the same way? By Paul Cleverley and Simon Burnett, Robert Gordon University, UK Exploratory search Subsurface search needs to guess what people might be looking for - and surprise them with something else - Paul Cleverley, researcher at Robert Gordon University The classic internet search engine, digital library and enterprise search have traditionally focused on precision and ranking. Exploratory search is where the question is not fully formed in the mind of the searcher. This is different to ‘known item’ (or lookup) search. It is possible the actual need may in part be stimulated by the search engine itself, with the search engine acting like a creative member of the team making suggestions from initial inputs. Faceted search The rationale is that as long as the specific web page or document you were seeking is on that first page, it does not matter how many results are returned. This approach has been incredibly successful, leading to Internet search engines like Google attracting a crowd nearing one billion users a week, of which 94 per cent never click past the first page of search results. But increasingly with Internet search, smart algorithms recommend or suggest related information, trying to predict what we need or may find interesting. In addition, social networks undoubtedly aid discovery. However, some researchers feel the overuse of historical usage and activity data within algorithms to make suggestions may place us in a ‘filter bubble’ constraining some potential serendipitous encounters. Enterprise search In an enterprise environment, significant frustration still exists where the success seen on the Internet seems harder to replicate inside an enterprise. Factors for unsatisfactory retrieval include investment levels, organizational culture, the nature of workplace tasks, information governance and interventions, small crowds, information structure and permissions along with information behaviours of staff and management. Faceted search shows a breakdown of what exists in the search results by various categories with counts, normally shown on the left hand side of the screen inviting further human interaction to browse and filter results. used to gather survey data from 54 petroleum engineers from over thirty oil and gas industry organizations. A need was identified for the ‘surprising’ as a search filter. The research found the most statistically frequent associations (to search terms) were often “too vague and no promise of telling me anything I didn’t already know”, “relevant but not interesting” and “contained few surprises”. However, algorithms such as mutual information measure appeared to generate more intriguing associations “useful for deep dives”, “might learn something” and “high on interestingness quotient, you can’t say where these results may lead you”. Algorithms for surprising These may be potentially useful options when you consider most enterprise searchers enter two words or less, searching increasingly larger haystacks of information, so most searches deliver hundreds or thousands of results. Further research presented at the International Conference on Knowledge Management used discriminatory word co-occurrence techniques surfacing potentially ‘surprising’ associations to search terms. But, it is difficult to represent the richness of a 50 page report with 6 topics. Furthermore, the same information item will always be represented by those same 6 topics, regardless of what search terms are used and where relevant matches are found inside the document. Initial results were promising. In an observational study of 53 geoscientists in two oil and gas organizations, 41 per cent felt current search interfaces used by their organization facilitated serendipity to a moderate/large extent, increasing to 73% with the introduction of certain algorithmically generated filters. One method to provide contextual based topic filters is word co-occurrence - using words that appear in proximity to the search terms found in documents. As put by one participant “It’s like open up the box for me and I’ll pick what does not fit with my brain, like one of those games”. Need to be surprising Recent research by Robert Gordon University published in the Journal of Information Science identified certain information needs with respect to faceted search refiners. Research was conducted using word co-occurrence stimuli generated from data provided by the Society of Petroleum Engineers, Geological Society of London and the American Geological institute. The stimuli was Surprising and serendipitous encounters occurred giving rise to learning experiences, “It is clear I underestimated the importance of carbonates in… this is immediately important for the research I am undertaking now”. Surprising associations can be unusual words or quite common words but appearing in an unusual or discriminatory context. For example, “What is interesting is that Halite is there for the Permian, but technically it could occur for Tertiary, Jurassic, (others), what is surprising is that it has not”. February / March 2015 - digital energy journal 11 Subsurface This may be detached from any initial specific intent, the surprising nature of the association enticing the searcher to drill down further which may lead to a serendipitous encounter. Enhancing creativity one person, may not be by another as suggested filter terms are compared with their own cognitive map, like a game of spot the difference. The challenge with text co-occurrence is to decide what to present to the user, minimizing distraction but offering potential surprises, combining with traditional controlled vocabulary (taxonomy) metadata approaches. What is deemed ‘surprising’ or ‘intriguing’ by Companies that adopt such practices, may experience more “happy accidents” in the user interface than those which do not. Paul Cleverley and Simon Burnett are researchers in the department of Information Management at the Aberdeen Business School at Robert Gordon University in Aberdeen, UK. Hadoop for oil and gas Hadoop, a new data storage technology, promises to make high volume data much easier to manage in the oil and gas industry. Alyssa Farrell of SAS explains how it works Hadoop is a new data storage technology which may lead to a big change in how the oil and gas industry manages big data. High-volume data, whether structured or unstructured, can be placed into an enterprise data hub (EDH) on Hadoop and prepared for further analysis without the time-intensive steps associated with the traditional relational database model. With a Hadoop “cluster”, both structured and unstructured data can be managed for use over long time horizons, in original fidelity, and integrated with existing infrastructure and tools. With Hadoop, organizations have a new way to think about data, transforming it from a cost to an asset. Geophysicists are already evaluating Hadoop as a technology to support processing seismic data from a multidimensional perspective, complementing the traditional processing sequence. “New technologies that reduce the latency of data for analysis, such as cloud applications and Hadoop, are significant game changers for the oil and gas business,” said Moray Laing, SAS Executive lead for Oil and Gas, formerly at Baker Hughes. “As a result, this industry is on the precipice of major change in their IT architectures.” vey of more than 400 practitioners about their big data efforts. Respondents were asked which database management systems (DBMS) were in use for big data management efforts. Analytics on Hadoop While traditional relational DBMS systems were at the top (38 percent), Hadoop was tied for second place (33 percent). SAS and Cloudera recently announced technologies that move the analytic functions directly within a Hadoop cluster. In addition, it was clearly evident that the phrase “big data” was synonymous with Hadoop, in the minds of those surveyed. A meteoric rise for a technology that only became commercially viable in the last five years. Deploying models directly in Hadoop reduces data movement and replication, saving time and resources - while strengthening data governance. For many organizations, establishing an enterprise data hub using Hadoop will be a costeffective solution for data capture of all data, structured and unstructured, in a secure, managed environment. When paired with additional technology applications to ensure data quality, and to visualize and analyze the data effectively, Hadoop is ready for prime-time. Software companies, like Cloudera and SAS are working together to provide processes and technologies that accelerate data-driven insights. Dave Cotten, whose team at Cloudera supports many US oil and gas companies, says that “Cloudera's oil and gas clients are realizing multiple revenue generating and cost savings opportunities. Big data trends Recently, The Data Warehousing Institute (TDWI) released "Managing Big Data," a report that explored trends in big data management. The report presents the findings from a sur12 “In addition, our customers typically improve preventative maintenance, greatly reducing costly downtime. “ “From real-time field operations feedback improving reservoir yields, to full-fidelity electronic well record management, to mining internal and public data to determine optimal well spacing, customers are obtaining deeper insights at lower costs provided by Hadoop in an enterprise data hub.” digital energy journal - February / March 2015 With all your data in one place, simple tabular data can mix with more complex and multistructured data to provide business insights never before possible. Organizations can run a variety of enterprise workloads, from batch processing to advanced analytics, in a secure, managed, governed environment. Early adoption of analytics on Hadoop has been popping up in seismology, asset optimization, commodity pricing strategies, and production optimization. Because SAS data visualization on Hadoop allows companies to interactively explore billions of rows of data in seconds. One common use case is for data validation, finding the outliers and flagging them for further explanation. Because you can look at both structured and unstructured data, like Twitter feeds or web traffic, in one place over time, there are applications for cybersecurity as well. Subsurface EMC and the future of seismic data David Holmes, chief industry executive with EMC’s Global Oil & Gas Program, explained what the future of seismic data management will look like Could future seismic interpretation could be done by crowdsourcing, asked David Holmes, chief industry executive, EMC's Global Oil and Gas Program “Companies should care more about this stuff. They have spent millions on acquiring it and the cost of managing it is an unmeasurable fraction of that,” he said. “Some companies do have a regulatory obligation to keep their data in perpetuity, and it doesn’t mean a rusty 9-track no-one can read.” At the recent Society of Exploration Geophysicists (SEG) event in Denver in October 2014, a company called Agile Geoscience ran a hackathon with 30 people in a room, asking them to write a ‘supercool geoscience application’. “A [typical] oil company is working with five seismic data storage companies, each with different cataloguing systems, all incompatible, three million media items, including two million 9-track tapes. David Holmes, one of the judges, selected as the winner a crowdsourcing “hot or not” tool for other people’s seismic interpretation. “There are a finite number of read heads for 9-track tapes,” he said. “They are not being manufactured any more. You log on to an online tool with your Google account, interpret some seismic data, and then rate other people’s choices. Some companies “are paying $10m a year in license fees for data they're not using but can't prove that they're not using,” he said. “This is the future, I'm convinced,” Mr Holmes said, speaking at the Digital Energy Journal Aberdeen conference on November 27, “Doing more with Seismic Data.” The trouble is, managing data is hard work, and it always easier not to do it. “Companies ask, shall we spend lots of time and money doing something hard with intangible business value, or do nothing,” he said. There are many more exciting things the industry could do, if the seismic data systems were on the cloud. One US company put all of its seismic data onto disk, and then hired 6 students from the Colorado School of Mines and gave them access to the entire seismic library, telling them “go and find some stuff.” Mr Holmes said it is a “mystery to me why we keep standalone workstation going as long as we have,” he said. Geophysicists still work on personal workstations, where they spend 20 minutes loading up all their data every morning. If they could work directly on a cloud system it would be a lot faster. Managing old seismic Yet still most oil and gas companies store their seismic data on tape, and have very little idea what they have, if they are storing multiple copies of the same data, or do not have what they thought they had. You can’t just copy seismic data from tape to disk, because the data will get corrupted. It needs to be transferred to a different format. Together with the data, you need to keep a scanned copy of the tape label, logs of the remastering process (gathering data from tape). “You need everything in your possession that will allow you to recreate that nasty crumbly 9 track tape,” he said. Data management processes In the future there will also be much stricter data management processes, he said. Many oil and gas companies already say that geoscientists may not load up data themselves, they must give it to a data manager, to load it and validate it, he said. There are software tools to make this process easier, for example where new data is loaded to a folder, then a data manager receives an email alert. The data manager can then check the data formatting and co-ordinates, make any necessary transformations and check the headers. Working with big data Some physical data storage companies are taking advantage of oil companies willingness to take the cheap and secure option over the short term. They offer a service where they store your data free of charge, but charge you big fees when you want to retrieve it, he said. Some cloud data services are trying to get away with the same business model. “The cost of retrieving the data can be gigantic.” The problem is that usage rates of seismic data is typically very low, with only small amounts of data retrieval over a time frame measured in decades, he said. But slowly, attitudes are changing, as companies realise the risk of not properly maintaining data assets, he said, and cloud solutions offer a cheaper alternative. Move away from tape Mr Holmes recommendation is to move away from tape. A side-effect of the growth of big data systems is that many companies now have multiple systems for storing data, including their normal archiving systems, high performance computing (HPC) enviroments, Hadoop environments. They might have the same data file in all of these systems. If they back up the data in each environment multiple times, they can end up with many copies of the data. “One company worked out they would have 17 copies of all of their data, if everything had gone well,” he said. As data volumes get bigger, keeping 17 copies of everything will get very expensive. “If we have any chance of surviving the next few years, it’s going to be crucial that we have a single instance of our data,” he said. “Or companies will make a fortune selling you vast amounts of storage you don't need.” A new term has been invented, “next generation data fabric”, which describes the enter- February / March 2015 - digital energy journal 13 Subsurface prise architecture for storing and managing information, he said. Companies will also use ‘object storage’ which means that the analytics tools can understand the different data storage systems you are using. The idea of ‘master data management’ will be redundant, because companies will be able to search all of their data at once. Geophysicists will be able to ask complex queries, like “show me all the files I have navigation for, which I don’t know about.” Or in more specific terms, “show me all of the navigation files which have a survey name which isn't in my survey master. “You can run that simple query against your entire landscape,” he said. View David Holmes’ talk on video at http://www.digitalenergyjournal.com/vi deo/1224.aspx Developments at LMKR Subsurface data and modelling company LMKR reports that it has formed a partnership with petroWEB, an oil and gas data and information management company based in Colorado, Canada and Houston. The agreement is for LMKR's "GeoGraphix" subsurface interpretation system to integrate with petroWEB's "Enterprise DB" exploration and production data management system, built on the PPDM model. Enterprise DB can serve as a corporate well master, well log repository and well file management system. By putting Enterprise DB together with GeoGraphix, you have a single system for managing large volumes of subsurface data, LMKR says. LMKR has also formed a technology partnership with LUMINA Geophysical, a company based in Houston which provides special tools for quantitative interpretation of the subsurface, based on a mathematical method called spectral decomposition. This allows more geological information to be extracted from geophysical data. As a result of this partnership, LMKR will release a new software tool called Predict 3D in early 2015. This is a multi-attribute inversion solution based on spectral decomposition. The multi-attribute inversion process predicts rock properties from well logs away from and in between the wells that have been used for correlation. This helps understand the nature of the reservoir away from the wells. LMKR has also made improvements to the user experience with its GeoGraphix 2014.2 subsurface software, improving seismic interpretation speed and capability, offering larger memory access and up-front well loading optimization. There is improved integration with depth geomodels. This means that users can easily depth convert faults and incorporate into a sealed earth model as well as combining seismic interpretation data and well picks into the geomodel. Enhancements to velocity modelling and depth conversion make it easier to depth convert seismic with velocity models generated from defined horizon-formation top relationships. LMKR has developed a 3D volume attribute generation tool, which can manage both trace based attributes (such as sample, window and Hilbert), and frequency based attributes. All of the frequency-based attributes use a patented spectral decomposition technique for higher resolution results. LMKR GeoGraphix 2014 also delivers tighter integration between geological and geophysical interpretations. "Optique" $17.5m EU oil and gas big data research project now mid-way "Optique", a 4 year, $17.5m oil and gas big data research project co-ordinated by a University of Oslo professor, is now in the midway stage. The project has EUR 9.7m funding from the European Union and is supported by DNV GL, Siemens, Statoil, and a German cloud data company called "fluid Operations". Optique aims to develop a software platform to help oil and gas users work with large and complex data sets, using "semantic technologies", which includes data meaning as part of the data model. The project was initiated in 2010 by University of Oslo (UiO) professor Arild Waaler, and launched in 2012. Total funding is Eur 13.8m (USD 17.5m) including Eur 9.7m from the 14 EU. Professor Waaler believes that this system will be different to other big data solutions, in that it will focus on understanding the complexity (including the variety) of the data, where most other big data solutions just focus on working with large data volumes. "Optique .. addresses trustworthiness by showing where data came from and how it has changed, providing transparency for the end user," he said. At the moment, geologists and engineers need to involve the IT department if they would like to post a complex query to their databases, but with the Optique system, they can get answers in minutes, he believes. 'This will open up new exploratory and inter- digital energy journal - February / March 2014 active ways of working as users get more relevant data sets in shorter time." The results of the research are planned to be presented in Høvik, Norway, in early 2015, with an aim to attract more companies to get involved, and ultimately develop methods and technology which will be used by the industry mainstream. 'We will deliver a good concept, but this will not be something that can be delivered to the industry two years from now," Professor Waaler said. "I hope that by then [early 2015] we have something so impressive that the industry will want to continue to fund this project. I am optimistic." Oil platform ––––––– –––––––––––––––––– North Sea, Norwegian o eg a Sector Simply when you need d the best. Tested to the limits. Ensuring ultimate relia ability of communications at se ea. We ve go We’ve ot you cove ered. As you strive to explore more of the world’s oceans it’s important to choose the right marittime satellite communications partner. 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Sharecat has a frame agreement with engineering company WorleyParsons, where Sharecat will provide specialist information management software and services to WorleyParsons to sell as part of its service to customers. Helping you put together offshore databases faster – Sturle Drageset, sales and marketing manager, ShareCat Sharecat of Norway is helping oil and gas companies put together structured information about all of the parts and components in their offshore operations faster, by sharing the data. The basic idea is that Sharecat maintains its own databases of standard information about millions of different parts. If you (as a customer) have a certain part on your platform, Sharecat might already have all the necessary specifications and materials lists (items you might need to purchase for it). So you can use Sharecat’s data rather than collect it again from scratch. In a greenfield project, all suppliers, EPC contractors and the end client will upload data and documents, review and collaborate in the same environment. Sharecat has been gathering its equipment catalogue for over 20 years and now has millions of pieces of data, said Sturle Drageset, sales and marketing director with ShareCat, speaking at the Digital Energy Journal Aberdeen conference on November 25, “Doing More with Offshore Engineering Data. Sharecat is based in Bergen, with offices in Aberdeen, London and Houston, and a reseller agreement with WorleyParsons in Australia. The database can be used both in greenfield projects, to help put together better part databases faster, and in brownfield projects, to help operators clean their data up. It also provides associated consulting services. Sharecat has global agreements with several oil majors, to put together a global catalogue of suppliers for Shell, and run a central information store for BP. It manages materials 16 The services are made available over the cloud as Software as a Service (SaaS). Data problems It is too common for operators not to have accurate records of what they have installed on their rigs, he said. We see inspection reports stating missing certificates, missing history, impossible to trace parts in the material master, and missing documentation and numbering information. This might be expected, when you consider that it is common for operators to take delivery of an oil rig or FPSO, but they do not receive the associated documents, part information and materials lists, in a usable format. The problem can be ignored until it is time to do modifications, but at this point, engineers can spend 2-3 hours gathering specification data (tags) for each component, before they can put together a purchase order for new materials. Every time any information is missing, you need to search for information and involve colleagues, which take up hours of expensive time. Poor information will lead to incorrect purchase, increasing the cost even more. On greenfield projects, it should be much easier to gather necessary information. But operators are often overwhelmed by the amount of data. The operator may deal with only a small number of contractors directly, but each contractor will go on to send hundreds (or thousands) of purchase orders to their suppliers and manufacturers, which generates an enormous amount of documentation. Sometimes documents for a single component (such as a motor) will be sent back to digital energy journal - February / March 2015 the operator many times, because this component is used as part of many different pieces of equipment. The information is sent by email, which means it easily gets lost, and no-one is sure if it is correct. Meanwhile, the operator’s projects staff do not necessarily have an incentive to make sure that the data is good, because after the project they will move onto a new project, and leave the data problem to the company’s operations staff. It can take many thousands man hours to put together a complete parts database for a new offshore asset, he said, so it is not a surprise that the work is often not done, and the project is handed to operations staff with only 30 per cent of information available. “We end up with poor and missing information in the material master,” he said. As the industry has to lower costs, the EPC (Engineering Procurement and Construction) companies must work more efficient and at the same time deliver better quality. This is what Sharecat’s products are tailored for, Mr Drageset said. We also experience drilling companies to struggle with procedures and routines to build up information correctly, he said. A lot of data is only entered as free text, and no possibility to retrieve crucial information in later maintenance, modifications and purchase of equipment and parts. Sharecat Sharecat’s service is to reduce the overall workload, by maintaining and continually updating the ‘shared catalogue’ of part data and deliver quality data to the clients. So for example data about a part such as a specific ABB motor, which might be used in thousands of different pieces equipment on many different offshore assets, information only needs to be entered once and re-used many times. Sharecat provides templates which can be given to engineering contractors so they know what data they need to provide, and which can be automatically uploaded into eEnable Your o S Supply Chain Founded in 2000, OFS Portal is an organization which consists of diverse supp plier members who are committed to promoting eCommerce and reducing cost. We have a no on-profit objective to ensure we promote the bestt approaches for the industry. In addition to advvocating strong protection for the security and confiden ntiality of electronic data, OFS Portal has gained the trust and confidence of the entire upstream oil and gas industry. We do this through our pro oactive advocacy approach toward best practices to reduc ce costs and complexity while increasing the speed of adoption. 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Sometimes the information is already in Sharecat’s database. If Sharecat already has both the part information and the material master (information about materials which might need to be purchased to go with that part), there is no need to enter the material master again. All the time, the quality of information in the database improves, in terms of accuracy and completeness. “We can evaluate and improve the information in the project as we go along,” he says. There is no need to keep sending data back to the vendor for checking, and enormous volumes of data can be handled. “Doing this, you will save a lot of time and money, you will provide correct information to operations.” “We capture information into templates, process into ShareCat, point out the incorrect information, then return it back to whoever is Delegates at Digital Energy Journal’s November Aberdeen conference “Doing more with Offshore Engineering Data” responsible to manage the information. All processes are controlled by a powerful workflow tool.” he said. Set requirements With Sharecat, you easily know if you have the information you need or not, and if you don’t have it, you can inform your suppliers. It is important to make sure the suppliers are aware of what they will need to provide in advance. “You have to set up all the requirements at the beginning of the project, how that is supposed to be delivered,” he said. “If you start asking for information after the work has been started it is too late.” “You can report daily, to see how to the different package suppliers progress on their deliverables.” If you don’t keep track of the quality of the data, you can end up with data which is as bad as if you were just receiving it ad hoc by e-mail. Watch Sturle’s talk on video and download slides at http://www.digitalenergyjournal.com/vide o/1245.aspx Drilling wells - with access to other companies’ data Mohammad Jahangir, senior drilling engineer with oil company VNG Norge, Stavanger, shared his thoughts about AGR’s “iQx” well planning software, which gives well planners access to all public data about wells drilled on the Norwegian continental shelf, while they plan their own wells Q What motivated you to choose iQx as your integrated solution in well projects? A We saw an opportunity to save our team’s time and resources by using a software tool that gave our engineers immediate access to all public drilling data from the Norwegian Continental Shelf (NCS). We also realised that we could improve internal skills transfer and learn from other operators’ operational experiences. As iQx has the functionality to visualise data in any format saved in public or company databases, the engineers save a lot of time normally spent on manual data search and processing. Q What are the benefits of this solution? A Being able to combine actual well data with location-specific experiences has allowed VNG to easier map potential challenges for the planned well and to undertake necessary actions to mitigate risk long before the project starts. 18 iQx has also been helpful in operations enabling easy check of abnormal well behaviour with relevant offset wells and to easily capture experiences in a new way involving the whole team and ensuring that the quality of these are up to the company’s standards. With iQx we easily capture the experience during the operation, classify it either to the location, rig or relevant equipment, and finally approve the experience in the project to the company’s standard so that we ensure the “lessons learned” have value for future operations. Q What do you use iQx for? A VNG uses iQx for offset analysis and saving experience. This could be for planning decided wells, following up our partners, making sure we are investing in the best possible relationships. Also for applications in licensing rounds, making sure we apply in areas where we believe we can perform well and showing the authorities that we fully understand the technical challenges in the areas we apply for. Experience transfer is something that we have seen as a challenge in several companies. Experiences are either left in the project files, never to be used again, or are of a character or quality that makes them impossible to use. digital energy journal - February / March 2015 Q Has it yielded any benefits / eased working processes in any way? A After installing iQx we have managed to focus time of our engineers on engineering instead of manual and time consuming data gathering and processing. We have seen that working in such a way has increased the quality of our offset analyses giving us a better platform for decisionmaking. Better decisions lead to safer and faster operations where we ultimately ensure a safe working environment for our people and higher probability of success in the projects that we choose. Drilling and production technology Books: Drilling Data Vortex, where bits meet the bits Dr Carlos Damski, CEO, Genesis Petroleum Technologies, a drilling data management company based in Perth, has published a book "Drilling Data Vortex, where bits meet the bits" - about how to use data to get a better understanding of your drilling operations. your company is improving over time, which factors in the well construction process have the most variability in them, or whether a certain well construction happened within a reasonably expected range or should be considered a 'problem well'. But what is proving much harder is actually having the data available which you can crunch. Here, there are good and bad solutions, as Dr Damski explains. If you have a computerised system which will tell a driller at the end of a 12 hour shift that they can't file a report because the computer does not accept the format of a certain piece of data, you're likely to find that your system is not getting used. But you can appoint a dedicated data quality control organisation, with the role of checking data as it comes in and taking appropriate steps. At a time when nearly every big business in the world is getting extremely advanced in its use of data for analysis and prediction, the drilling industry is starting to feel left behind. Drilling is still an environment where the person with 30 years experience tends to win the argument, even if the data shows there is a better way of doing it. The data management techniques are not particularly difficult technically - for example, you can crunch the data to show how You don't want to throw any data away, even the bad data, but you do want to keep a central database of data which everybody can trust. The results of the analysis can be enormously valuable, if it enables you to make better financial predictions about the cost of drilling a certain well in advance, you can predict likely problems or areas worthy of particularly high attention, and get a good understanding of where your drilling team is learning how to do it better, and where they aren't. The drilling sector has a lot of variability and unexpected events, and lots of scope for learning. All of this raises an additional question who is going to implement all of this stuff? There is still a big gap in the architecture of professions - with drilling engineers on one hand focussing on getting the drilling done, and the IT department on the other extreme often fixing problems and slow to respond to requests to provide data. There is a growing league of data managers but it does not seem to be filling the gap, in drilling at least. This book does a good job of making the business case for more emphasis to be placed on this middle space. Perhaps most important of all - this book is easy to read. So many oil and gas technical writers seem to believe that their priority is to be cutting edge technically, as though they are writing in a quasi-academic world where the most important thing is to say something new, or which sounds new, rather than to prioritise managing the mental load on the reader. The industry needs more books like this. Available on Amazon on print ($27) and Kindle ($23) Events 2015 Non-seismic Geophysics Transforming Sub-Surface interpretation London, 19 Feb 2015 London, 13 Apr 2015 Finding Enough Oil & Gas in NW Europe Doing more with Subsurface Data London, 12 Mar 2015 Stavanger, 05 May 2015 Transforming Sub-Surface Interpretation Doing more with Production Data Aberdeen, 17 Mar 2015 Stavanger, 06 May 2015 Doing more with Subsurface Data Finding Oil in Atlantic Basins Aberdeen, 18 Mar 2015 London, 27 May 2015 February / March 2015 - digital energy journal 19 Drilling and production technology Formatting data for different devices Oil and gas employees want to access their data with many different devices with different screen sizes, with data filtered according to their role. You can build a data structure to ensure everyone gets the data they want, for the device they use, writes Dr Arup Ratan Dr Arap Ratan Ray The Real Time Data Convergence for Multiscreen Displays (RTDCMD) framework gathers data from multiple sources scattered over large, geographically separated areas. This real-time data, once gathered, converges into one central point before analytics are applied. The data is then filtered to determine what data is relevant to whom, before being shared with different stakeholders in various locations. This filtration is essential as different stakeholders will be interested in different data points and perspectives, therefore tailoring the data that is presented speeds up the concerned person’s understanding by limiting the amount of irrelevant data to sift through. Due to the sheer magnitude of an oil field, the amount of data that could potentially be generated risks swamping the stakeholder if left unfiltered. In contrast, applying analytics in- stantly makes the data more manageable, enabling staff to react and take decisions more efficiently in response to the data presented to them. The use of multiscreen devices that are now popular with end users has amplified the transformation in industrial monitoring. If we look at how this applies to the oil and gas industry, the different stakeholders for the plant as well as field personnel use different visualisation screens and hand-held devices. The emerging IT and operational technology (OT) ecosystem consists of devices, sensors, real time data, analytic engines, always-on mobile networks and powerful mobile applications. Central database The key to successfully using this ecosystem is to accumulate the data in a large and central database. The central database enables businesses to have access to a single source of truth. Above this is a layer of real time analytics that distributes actionable insights to different screens for consumption based on user roles and needs. Benefits Data is presented to users from a consistent database enabling reliable collaboration. Data is filtered and in many instances analysed before it is sent to the end user. This showcasing of only relevant data/alerts based on access levels drives quicker decision-making and enhances data security. There is a reduction in data duplication and a concurrent increase in data consistency which increases the reliability, speed and efficiency of data usage. Technologies The ability to integrate data and systems at all three levels (machine, plant, enterprise) is reliant on the strength of technical competencies and partnerships around the RTDCMD framework. The extensive ecosystem of partnerships required for this includes engineering and automation specialists and Information Technology providers. For example, a very large oil and gas major with global operations leveraged RTDCMD technology by creating a Collaborative Work Environment (CWE). RTDCMD can be particularly helpful in complex environments where safety is a critical factor. M2M platforms and applications, with RTDCMD as the backbone, can orchestrate access controls and authorisation levels to ensure accidents and security lapses are eliminated. ClampOn - subsea vibration monitoring Subsea sensor company ClampOn of Bergen, Norway, reports that it recently completed a job to monitor vibration on a subsea template at 330m water depth. The operator had to close down production from a subsea well due to suspected vibration and needed urgent assistance to measure and confirm actual vibration level. 20 vessel at the docks, where all the equipment was loaded. Once offshore, the ClampOn vibration monitors were deployed and installed by ROV and connected to the ClampOn PC with software topside on-board the vessel. Within 2 days, Clampon was able to test, prepare and ship a complete vibration measuring system, with two vibration monitors, a specially adapted retrofit clamp, a 500 metre reel of cable, an ROV basket and a PC with ClampOn vibration monitoring software. Data was gathered and sent in real time to ClampOn's file server, from which the operator's own vibration experts downloaded the data for further processing and analysing. The vibration test was completed and the operator received confirmation that vibration on the subsea module was outside acceptable levels. Two experienced ClampOn Service Engineers were mobilized and met the support Clampon has services to measure subsea vibration, sand production and leakages. Other digital energy journal - February / March 2015 typical subsea vibration jobs include vibration on large subsea flapper valves, vibration on subsea flowlines and vibration from chemical injections ClampOn Subsea Vibration Monitor, rental set. Engineering Information AS It Should Be Datum360 delivers Software as a Service (SaaS) and consultancy to help Oil & Gas companies specify, capture and manage engineering information for capital-intensive projects and operations. www.datum360.com +44 3333 441 882 [email protected] MAPPING STANDARDS: A CORE COMPETENCY OF EVERY GEOSCIENTIST Maps are a canvas used to express complex situations to help support difﬁcult decisions. In exploring the subsurface, maps serve a number of important purposes; recording and storing information; supporting the analysis of a range of subsurface data; and presenting and communicating information and understanding. Map creation should be a core competency of every geoscientist, used to express complex situations to help support difﬁcult decisions. Our consultants can help E&P companies deﬁne and implement appropriate mapping standards that will help geoscientists present a clear, consistent and concise suite of maps for a variety of purposes where having deﬁned mapping standards has enabled the geoscientists to spend more of their time focusing on the technical content. Petrosys is a powerful subsurface mapping system that brings all your critical knowledge together on one mapping canvas, our approach to surface modeling enables you to resolve complex challenges and to communicate geological information necessary for decision makers to take the right action. Learn more at www.petrosys.com.au/transcend.
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